March 6, Docket No. PHMSA : Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations

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1 DOT Docket Management System U.S. Department of Transportation Docket Operations, M-30 Room W New Jersey Avenue, S.E. Washington, D.C VIA E-GOV WEB SITE ( Re: Docket No. PHMSA : Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations RIN 2137 AE59 Good afternoon: Per the notice of proposed rulemaking issued by the Pipeline and Hazardous Materials Safety Administration ( PHMSA ) on November 28, 2011, and published in the November 29, 2011, issue of the Federal Register, 76 Fed. Reg ( Proposed Rule ); and the notice of extension of comment period issued February 2, 2012, and published in the February 3, 2012, issue of the Federal Register, 76 Fed. Reg. 5472, the Interstate Natural Gas Association of America ( INGAA ) submits the following comments. INGAA is a non-profit trade association that represents the interstate natural gas pipeline industry. INGAA s members are subject to comprehensive safety regulation by PHMSA, and their interest in the Proposed Rule is self-evident. The Proposed Rule addresses a number of topics, and INGAA is not commenting on all of them. The topics INGAA is addressing are presented in their order of importance to INGAA s members. The comments close with remarks addressing the safety regulation of farm taps, a topic that is not covered in the Proposed Rule but should be. COMMENTS I. Odorization of Gas Transmission Lateral Lines: Proposed Amendment of 49 C.F.R (b)(3) Instead of adopting the proposed amendment, which increases regulatory confusion and adds to the issues already surrounding odorization, PHMSA should convene a public hearing or workshop to develop the fundamental regulatory changes needed to align PHMSA s policy objectives with common pipeline configurations. INTERSTATE NATURAL GAS ASSOCIATION OF AMERICA 10 G STREET, N.E., SUITE 700 WASHINGTON, D.C

2 Page 2 of 12 Observing that Section does not specify a clear method for calculating the length of a lateral line, and that has led to inconsistency in applying the odorization requirement, PHMSA proposes to revise section (b)(3) to read: In the case of a lateral line which transports gas to a distribution center, at least 50 percent of the length of that line is in a Class 1 or Class 2 location as measured between the distribution center and the first upstream connection to the transmission line; [proposed addition in bold]. The proposed amendment does not provide a clear method for calculating the length of a lateral line; if anything, it adds confusion and brings up other issues. Until now, INGAA and its members thought lateral, as used in section (b)(3), referred a particular group of transmission lines that transported gas to a distribution center. The proposed amendment suggests that a lateral line is not a transmission line, but a line that provides a link between a transmission line and a distribution center. For common pipeline configurations, the proposed amendment s apparent distinction between lateral lines and transmission lines would cause parts of lines to become subject to additional safety requirements, i.e., odorization, not because they changed function; not because of changes in the risk to public safety; but solely because branch lines are tapped into them. The proposed amendment contradicts established industry practice without any evidence of a resulting safety benefit (and certainly with no evidence showing that the resulting safety benefit justifies the amendment s cost). The natural gas industry considers lateral lines to be any lines that branch off other lines. Laterals are not a distinct classification of lines; rather, laterals are described according to their function, (e.g., transmission, distribution or gathering.) This is the way most transmission operators have applied the term lateral in analyzing the odorization requirements of section (b) and, more specifically, in determining which lines are exempt from odorization under section (b)(3). There is no evidence of record or otherwise suggesting that the industry s understanding of lateral has caused any safety issues. If there is a need to clarify what lateral means, the industry s commonly used definition more than adequately serves the interest of public safety and PHMSA should adopt it. The effect of inconsistently or unfairly applied odorization requirements is significant. On May 9, 1975, in issuing changes to Section by making odorization applicable to certain parts of transmission lines (prior to this, such lines were never considered necessary to be odorized), the Office of Pipeline Safety (OPS) acknowledged that for transmission lateral lines that transport gas to distribution centers: [T] he terminal portion of a lateral line generally lies in a class 3 or 4 location and under the proposed rule would have been subject to the odorization requirement. Because in most cases, the segment of line to be odorized is short, commenters argue that the costs of installing and operating odorizers would far exceed the safety benefit. OPS agrees with these comments. The final rule therefore, in Section (b)(3) exempts odorization

3 Page 3 of 12 of gas in a transmission line used in transporting gas to a distribution center if 50 percent of more of the line is in a Class 1 or Class 2 location. 40 Fed. Reg While the Proposed Rule states that the proposed changes would impose minimal (if any) burden, 76 Fed. Reg. at 73570, the proposed change to section (b)(3) could be construed in ways that impose a significant burden on operators for safety benefits that are minimal at best. Comprehensive change is necessary, and the first step toward achieving comprehensive change would be for PHMSA to convene a public hearing or workshop where the various configurations can be examined in detail and the objectives behind the odorization rules can be refined. Only then can stakeholders develop the definitions and rules necessary for odorization to occur where safety warrants, 1 and for operators and regulators to reach a clear and shared understanding of what the rules require in the field. INGAA also would like to see some further exemptions to the odorization requirements. These examples would be similar to those provisions granted to Kern River Gas Transmission Company in their 2009 waiver. The exemptions included more frequent leak surveys and line of sight pipeline markers in lieu of odorization. II. Responsibility to Conduct Construction Inspections: Proposed Amendment of 49 C.F.R Instead of the proposed amendment, PHMSA should adopt an amendment that makes it clear that the separation should be between the individual(s) who inspect a task the individual(s) who performed it, rather than the companies employing them. Agreeing with the National Association of Pipeline Safety Representatives (NAPSR) that a transmission pipeline or main cannot be inspected by someone who participated in its construction, PHMSA proposes to amend 49 C.F.R as follows: Each transmission line and main must be inspected to ensure that it is constructed in accordance with this subpart. An inspection may not be performed by a person who participated in the construction of the transmission line or main. [proposed addition in bold]. INGAA agrees that potential conflicts of interest should be removed from construction inspection. Where construction is performed by a contractor, the inspection should be performed either by a contractor employee who did not perform the work being inspected, or by individuals who are not employed by or affiliated with the contractor. Where construction is performed by 1 As a starting point for developing logical, integrated, comprehensive and performance-based odorization requirements, the public hearing or workshop should address whether odorization is the most effective leak detection methodology. Odorization is tried and true, but there are newer, more sensitive technologies that could be applied to transmission lines such as those transporting gas to a distribution center or single-user system.

4 Page 4 of 12 the operator, inspection should be performed by individuals who did not perform the work being inspected. If it were clear that person, as used in the proposed amendment, referred strictly to the individuals performing inspections and performing the tasks undergoing inspection, the possible grounds for conflict would be relatively narrow. Unfortunately, the proposed amendment s reference to person could also be read to refer to the corporate entities, i.e., the legal persons, employing the inspectors and workers. According to the Proposed Rule, the corporation-as-person reading is evidently NAPSR s position: Specifically, NAPSR believes that contractors who install a transmission line or main should be prohibited from inspecting their own work for compliance purposes. Proposed Rule, 76 Fed. Reg (emphasis added). Reading person to mean company, as NAPSR apparently advocates, would have a significant, costly impact on natural gas pipeline operations. Many pipeline construction projects are conducted by operating company personnel. In some operating companies entire divisions of personnel have been created for the express purpose of pipeline facility construction. If the proposed language is intended to prevent an operating company from inspecting its own work, thus forcing it to hire an outside inspector, presumably at the operating company s expense, INGAA opposes the proposed language. In addition, the proposed amendment apparently would provide no de minimis exception to the outside inspector requirement; if an INGAA member s employees did the work, the INGAA member would have to hire outside inspectors no matter how small the project. The Proposed Rule does not mention these costs, let alone demonstrate that imposing them is justified by a resulting safety benefit. A separate but equally serious problem concerns the scope of persons who would be excluded from performing inspections. As proposed, a person who participated in the construction of the transmission pipeline or main cannot inspect it. This implies that a person who performs one construction task cannot inspect a different task. For example, a person having the necessary training and experience to inspect welds could not do so if they had performed another construction task (e.g. installed pipe in the ditch). To ensure compliance, the party performing the construction must use an outside inspector who is completely removed from the project. Hiring additional personnel solely to have inspectors who did not participate in the construction is burdensome. Basically, for every construction project, no matter how small, an operator would have to hire several independent inspectors: one for welding, one for pipeline lowering, one for pipe inspection, one for coating inspection, etc. For a small project, this may double the amount of resources required; one person to perform the task and one to inspect. The problem is compounded for the thousands of construction tasks that operators perform with small crews that each contain a handful of individuals. Many DOT-regulated industries inspect their own work and these industries have experienced little to no construction-related integrity issues. INGAA member companies have for decades conducted self-inspections of operator-conducted construction projects, and there is

5 Page 5 of 12 no evidence that construction projects conducted and inspected in this manner are any less safe or resulted in lower integrity than any other method of construction and inspection. It is also not clear why this requirement has not been applied to other jurisdictional facilities. Gathering lines are not included in this requirement; service lines are not included; pipeline facilities other than transmission lines and mains, such as all parts of a distribution system or transmission system or gathering system, are not included. To address these concerns, PHMSA should promulgate the following amendment, which would prohibit a single individual from both performing a construction task and later inspecting it: Each transmission line and main must be inspected to ensure that it is constructed in accordance with this subpart. A required inspection may not be performed by the individual who performed the construction task requiring inspection. [proposed addition in bold]. III. Testing Components Other Than Pipe Installed in Low-Pressure Gas Pipelines: Proposed Deletion of 49 C.F.R (d) and Addition of 49 C.F.R (e). Consistent with extending current pressure testing regulations to components installed in lowpressure gas pipelines, PHMSA should expand the list and sources of standards that can be used to establish pressure ratings. As proposed, components for pipelines operating under thirty percent (30%) of specified minimum yield strength (SMYS) would become subject to the same restrictions and exemptions for pressure testing that apply to components for pipelines operating at or above thirty percent (30%) SMYS. The exemptions continue to allow components with a pressure rating established through applicable ASME/ANSI or MSS specifications but do not extend the exemption to components with pressure ratings established using other standards. Especially for lower stress operations, many more standards by many more organizations provide pressure ratings of components. This is particularly true for plastic pipe and components, which are often used for lower pressure operations. PHMSA therefore should review all referenced standards and provide the exemption for all standards that establish pressure ratings. Standards to be reviewed include ASTM standards, PPI standards and API standards. As an alternative to referencing a list specific standards organizations, which is subject to change, PHMSA could incorporate the standards referenced in 49 C.F.R and amend section (e)(3) to add: The component carries a pressure rating established through applicable specifications listed in 192.7, or by unit strength calculations as described in

6 Page 6 of 12 IV. Components Fabricated by Welding: Proposed Addition of 49 C.F.R (e). Instead of the proposed addition, PHMSA should clarify that components rated under the ASME code do not require testing beyond the ASME code. If PHMSA adopts the current recommendation, it should also adopt a provision exempting facilities installed before the effective date of the amendment. Under the Proposed Rule, a component which has a design pressure established in accordance with section (a) or (b), and which is subject to the strength testing requirements of section (b), must be tested to at least 1.5 times the maximum allowable operating pressure (MAOP). The addition of this paragraph is not a clarification, but a departure from the previous understanding and practice of both PHMSA and the operators. If applied retroactively, this change will place many facilities constructed after the change in the pressure test requirements in ASME BPVC Section VIII, as well as many facilities uprated under special permits, in violation of the code. The ASME BPVC Section VIII was changed in Based on publications from the Third Annual Pressure Industry Conference held in February 1999, the change in the pressure test factor from 1.5 to 1.3 was made in conjunction with changes to the 3.5 design factor in the 1998 edition, addenda 1999, which are more restrictive and increase the safety factor for ASME vessels. Section (b) clearly emphasizes that the BPVC is the primary standard for design, construction and testing of pressure vessels when it states the following: (a) (b) Except for branch connections and assemblies of standard pipe and fittings joined by circumferential welds, the design pressure of each component fabricated by welding, whose strength cannot be determined, must be established in accordance with paragraph UG 101 of section VIII, Division 1, of the ASME Boiler and Pressure Vessel Code. Each prefabricated unit that uses plate and longitudinal seams must be designed, constructed, and tested in accordance with section I, section VIII, Division 1, or section VIII, Division 2 of the ASME Boiler and Pressure Vessel Code,2007, except for the following: (1) Regularly manufactured butt-welding fittings. (2) Pipe that has been produced and tested under a specification listed in appendix B to this part. (3) Partial assemblies such as split rings or collars. (4) Prefabricated units that the manufacturer certifies have been tested to at least twice the maximum pressure to which they will be subjected under the anticipated operating conditions.

7 Page 7 of 12 These comments also apply to the proposed change of (b)(3), which references the proposed (e). These sections of Part 192 and the ASME Boiler and Pressure Vessel Code revision history make it clear that the Proposed Rule is suggesting revisions that will require a number of operators to make substantial and costly changes. Station piping often includes fabricated sections that are assembled at the construction site. Many of these sections, such as compressor bottles, coolers, and inlet scrubbers and separators, are tested and certified by their manufacturers. Requiring a second test at the construction site, as proposed, would depart sharply from common practice, add costs that are not justified by a safety benefit, and potentially invalidate the manufacturers compliance certificates. It is likely that several operators may have numerous vessels installed after the change in the ASME code (circa 1999) which were only tested to a factor of 1.3 rather than 1.5 and only tested for one hour rather than eight hours. Other facilities were uprated under MAOP special permits, subject to PHMSA s close supervision and approval, by relying on the reduction in test factors in the ASME code to rerate the code vessels for the increased MAOP. Retesting or replacing these in service components would be very expensive and would require several years. INGAA is not aware of any failures due to the reduced testing requirements in components rated under the ASME code currently incorporated by reference into 49 C.F.R. Part 192. PHMSA should adopt an alternate clarification that these components do not require testing beyond the ASME code. If PHMSA adopts the current recommendation, it should clarify that the amendment applies only to components placed into service after the amendment s effective date. Another significant change in this proposed regulation is that the requirements for pressure testing in (b) specifies: In a Class 1 or Class 2 location each compressor station, regulator stations, and measuring station must be tested to at least Class 3 location test requirements. Section (a)(1) refers to to determine the pressure test factor. As written, a vessel in a Class 1 or Class 2 location that is not in a compressor, regulator or measuring station only has to be pressure tested to the factor associated with the class location. The proposed change to the regulations would require pressure testing of all vessels and other components fabricated by welding to be tested to Class 3 location requirements regardless of whether they are in a compressor, regulator or measuring station. This is a significant change to the regulations with far reaching impact for operators. In addition, the new regulation would conflict with the requirements of (b).

8 Page 8 of 12 V. Transportation of Pipe: Proposed Deletion of 49 C.F.R (a)(2). If PHMSA promulgates this amendment, it should specify that the use restriction does not apply to any pipe already installed or to any pipe transported after 49 C.F.R initially took effect. According to the Proposed Rule, eliminating the section (a)(2) exception will have minimal impact on operators because the resulting regulations will only affect pipes that were transported over 40 years ago and have not yet been installed: The amount, if any of pipe transported prior to November 12, 1970, which remains in operator stockpiles is likely to be very small. Therefore, this change will have minimal impact on pipeline operators. Proposed Rule, 76 Fed. Reg. at INGAA agrees with PHMSA s analysis. Lifting the section (a)(2) exclusion only affects stockpiled pipe transported before November 12, 1970, and the amount of that pipe is very small. Assuming PHMSA maintains this interpretation of this section of the Proposed Rule, INGAA does not object to the deletion. A change in interpretation could have significant consequences, and INGAA and its members reserve the right to submit comments and pursue other legal redress should PHMSA reinterpret its action to impose regulatory burdens on a broader range of pipes. VI. Qualification of Welders and Welding Operators. PHMSA should amend its proposal to correct what appear to be two inadvertent errors and to incorporate by reference Appendix B to API Standard 1104, which covers qualification of procedures and welders for in-service welding. INGAA has identified what it believes is an inadvertent omission in the proposed language of section INGAA understands that the welding-related changes are primarily to recognize and distinguish between a welder and a welding operator, and INGAA agrees with this distinction. Section also clarifies the equivalence of acceptance standards established in Section 9 and Appendix A of API Standard 1104, as applicable. However, the proposed language for section (c)(1) contains an oversight related to this equivalence. That section says, in part: A welder or welding operator qualified under (a) (1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder or welding operator has had one weld tested and found acceptable under section 6 or section 9 of API Standard 1104 (incorporated by reference, see 192.7). Sections 6 and 9 of API Standard 1104 relate to workmanship criteria only. The proposed language would thus appear to preclude the extension of qualification of a welding operator

9 Page 9 of 12 whose welds are regularly being assessed per the criteria in Appendix A, which is regarded as equivalent to Section 9. It is reasonable to allow the extension of qualification for a welding operator whose work has been acceptable under the Appendix A criteria. INGAA therefore suggests the following modification to the language proposed in the Notice: A welder or welding operator qualified under (a) (1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder or welding operator has had one weld tested and found acceptable under section 6, or section 9 or Appendix A, as applicable, of API Standard 1104 (incorporated by reference, see 192.7). [proposed deletion indicated by strikeout; proposed addition in bold]. While it is amending the welding regulations, PHMSA should take the opportunity to formally incorporate by reference Appendix B to API Standard 1104, for in-service (also known as live line ) welding. PHMSA covers Appendix B in its training, and the regulated community widely uses Appendix B to develop welding procedures for live line welding. Still, some inspectors insist that procedures that reference Appendix B are not in compliance with Part 192 because Appendix B is not incorporated by reference. PHMSA should use this docket to address this enforcement problem. INGAA also has identified what it believes to be a typographical error in section (d)(2)(ii). INGAA believes that section is intended to read: Two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part or for a welder or welding operator who works only on service lines 2 inches (51 millimeters) or smaller in diameter. [proposed deletion indicated by strikeout; proposed addition in bold]. VII. Alternate MAOP Notifications: Proposed Amendments to 49 C.F.R (c)(1) and (c)(8). The amended notice requirement for alternate MAOP pipelines should apply only prospectively, and the regulations should include an alternative notice period measured from the placement of a pipe purchasing order or the start of pipe manufacturing. PHMSA proposes two revisions to (c). The first would require operators to notify PHMSA field offices 180 days prior to the start of pipe manufacturing and/or construction activities for alternative MAOP (AMAOP) pipelines. The second is a revision to (c)(8), covering class upgrades, to correct a reference to (a). Section (c)(1) currently requires operators to: notify each PHMSA pipeline safety regional office (and the State agent as appropriate) where the pipeline is in service of its election with respect to a segment at least 180 days before operating at the alternative maximum allowable operating pressure.

10 Page 10 of 12 The current provision applies to in-service AMAOP pipelines, and these pipelines should continue to be subject to this provision regardless of whatever notification requirements emerge from the Proposed Rule. In-service pipelines that otherwise meet the design, construction, and operating requirements of Part 192 for AMAOP pipelines should not be prevented from operating as an AMAOP solely because notification was not provided prior to its manufacture and construction, which occurred at some point in the past. Similarly, the 180-day notification requirement should not apply to pipe that was manufactured prior to the effective date of new regulation. Additionally, pipe that is manufactured in small quantities and installed in AMAOP pipelines for maintenance or regulatory compliance (repairs, class changes, etc.) should be exempt from this notification requirement. This pipe can be made in small batches by several mills and installed at various locations. In these cases it is not practical to provide advance notifications and INGAA does not believe this is the intent of the proposed revision. For new pipeline projects the application and permitting process can extend over months or years before approval to construct is granted. Once this approval is obtained, pipe orders are placed and production dates are established. The interval from the time the pipe is ordered until the start of production is sometimes less than 180 days making it impractical to provide the required notice as the proposed rule is currently worded. To address this INGAA recommends that the wording be changed to 180 days or 10 business days before the operator places a purchasing order for the pipe or the pipe starts being manufactured. INGAA has no objection to the proposed revision to (c)(8). The current reference to (a)(3)(i) is not accurate as it applies to non-amaop pipelines and represents only one of three alternatives provided in (a) for managing changes in class location. VIII. taps. Farm Taps INGAA would also like to offer comments on one additional subject, treatment of farm Farm taps are typically short, small diameter, low stress, transmission line pressure takeoffs to a regulator and meter set, which provide domestic gas to a farm or other similar residence. Such taps were usually provided as a courtesy or as part of the compensation to the landowner for granting the pipeline easement. Piping downstream from the outlet of the meter is generally customer-owned. The transmission company may own, operate and maintain all the facilities from the main line take-off to the outlet of the meter, but the regulator, meter and odorizer, if present, also could be owned and operated by another entity, such as a local distribution company (LDC). The presence of an intermediate LDC and the actual point or points of ownership and operating responsibility vary from company to company, state to state, and location to location.

11 Page 11 of 12 Transmission companies have historically regarded farm taps as part of their transmission systems and have operated and maintained them as such. This treatment is consistent with how farm taps are treated under federal law. Farm taps are part of the transmission systems certificated by the Federal Energy Regulatory Commission. In addition, treating farm taps as transmission pipes has been consistent both with the guidance PHMSA provided in a 1979 interpretation and with the farm tap diagram published on the PHMSA web page. Aside from differences in diameter, flow and stress level, farm taps are functionally very similar to direct sales lines, which are now regarded as part of an operator s interstate transmission system if they originate from an interstate transmission line. The design, construction, operations and maintenance procedures of the transmission operators have proven effective and sufficient for the farm taps on their systems. The interstate transmission system contains thousands of farm taps, and INGAA s members are unaware of any deaths, serious injuries or significant property damage in over 60 years of farm tap operation. Last year, in response to an inquiry requesting confirmation of the status of farm taps, PHMSA set all this history and precedent aside, declaring that farm taps are, by definition, distribution lines and that a distribution integrity management plan (DIMP) is required for them. This extraordinary reversal in course rested on three interrelated definitions in section 192.3: Distribution line means a pipeline other than a gathering or transmission line. Gathering line means a pipeline that transports gas from a current production facility to a transmission line or main. Transmission line means a pipeline, other than a gathering line, that: (1) Transports gas from a gathering line or storage facility to a distribution center, storage facility, or large volume customer that is not down-stream from a distribution center; (2) operates at a hoop stress of 20 percent or more of SMYS; or (3) transports gas within a storage field. Within these definitions, distribution lines are defined by exclusion of the other two types listed, distribution center is not defined, large volume customer is not precisely defined, and the hoop stress differentiator between transmission and distribution is not based on the function performed by the line. Although PHMSA s 2011 response only addresses the necessity of a DIMP, declaring these typically short (a few feet to a few hundred feet in length) and small (typically 1 to 2 inch diameter) segments to be distribution lines subjects the operator to the entire array of operation, maintenance and reporting requirements particular to distribution lines. Many of these distribution line requirements are predicated on the assumption (usually accurate) that these lines generally operate in urban or suburban areas (or, put differently, in industrial, commercial or residential environments). This is seldom the case for farm taps. The distribution line requirements necessitate an operator having not only a DIMP, but also the procedures, programs, qualifications, systems, records and reporting, including annual reports, required specifically for distribution systems.

12 Page 12 of 12 Treating farm taps as distribution lines runs contrary to past PHMSA practice, to past industry practice and reason. For transmission operators, classifying farm taps as distribution lines would dilute resources, artificially fragment operational approaches to maintaining system integrity, introduce confusion where none exists today, and, most importantly, provide no incremental safety benefit. In fact, the burdens, confusion and diversion of resources could likely be detrimental to safety. INGAA therefore urges PHMSA to reconsider its recent change in position. A reasonable alternative would be to recognize the similarity of farm taps to direct sales lines, and to allow interstate transmission operators to continue to consider and treat farm taps as part of the interstate transmission system from which they originate and to which they remain attached. INGAA understands that operators of intrastate transmission systems, distribution systems and gathering systems may also have farm taps originating from their lines. If PHMSA believes these operations leave gaps in safety regulation, PHMSA should address troublesome cases specifically, rather than by imposing wholesale changes to successful programs and needlessly disrupting them. Should PHMSA decide to further investigate this subject, INGAA and its members will participate enthusiastically in a targeted study, workshop, public meeting or other vehicle to gather and share such information and viewpoints. If the farm tap issue is not addressed in this docket, INGAA is also prepared to voice its concerns through a petition for rulemaking. CONCLUSION INGAA appreciates the opportunity to comment on the Proposed Rule. For any further information regarding these comments, please contact the undersigned. Respectfully submitted, /s/ Dan Regan Regulatory Attorney Terry D. Boss Senior Vice President of Environment, Safety and Operations Interstate Natural Gas Association of America 20 F Street, N.W., Suite 450 Washington, DC (202)